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Long, Hot Summer: Potential for Double-Digit Gas Prices?

If April-June weather is roughly in line with the National Weather Service (NWS) outlook, U.S. natural gas storage could enter July down about 500 Bcf compared with a year ago, which one analyst said may set up the potential for double-digit gas prices this summer. However, the "giddy gas bulls" are ignoring an expected increase of hydroelectric output, which could displace a lot of West Coast generation, according to another analyst.

Stephen Smith Energy Associates Inc. of Natchez, MS, detailed its expectations for gas prices in the coming months in a monthly outlook report. Smith's analysis follows an NWS forecast in late March that calls for above-normal heating degree days (HDD) in key eastern and Midwest energy markets. The NWS also is calling for above-normal cooling degree days (CDD) "for regions in which gas-fired power generation [is] most important."

Based on the NWS forecast and internal modeling, Smith analysts concluded that there is a potential for gas prices to hit $10-12/Mcf Henry Hub this summer -- if the summer months are hot. Smith's base-case outlook is "somewhat more moderate." It assumes:

"This HDD/CDD scenario, along with other assumptions, leads to a projected storage surplus of 224 Bcf on July 4, which would be about 500 Bcf lower than the storage surplus of one year earlier," Smith noted. The energy team estimates a late May gas-to-residual spread in the range of minus $1.75/MMBtu to minus 75 cents/MMBtu. An assumed New York Hub 1% residual price of $11/MMBtu for late May would imply a "likely June Henry Hub bidweek price range of $9.25-10.25/MMBtu (midpoint = $9.75/MMBtu)."

The June 2008 Henry Hub contract closed March 20 at $9.23/MMBtu, Smith noted.

"On Jan. 11, the gas storage surplus [over the five-year average] was 631 Bcf. By March 20, this surplus had declined by 261 Bcf to 370 Bcf," and gas prices increased more than $1/MMBtu over the 10-week span, the Smith team noted.

Also playing into the gas storage and price picture is the decline in domestic liquefied natural gas (LNG) imports, said the analysts. As of March 20, LNG imports had averaged 0.7 Bcf/d this year, which is about 2 Bcf/d below year-ago levels.

"We expect to see a seasonal increase beginning in April but we remain doubtful that this year's second quarter LNG imports will match the 3.1 Bcf/d average recorded for last year's second quarter," said the analysts. Last year's spring and early summer surge in LNG imports to the United States "was due mainly to a spring 2007 European gas glut, which was the result of a very mild European winter. In sharp contrast the last few months have seen a comparative dearth of LNG imports because LNG netbacks to both Asian and European LNG markets have been substantially higher than those for U.S. markets."

Total gas production also has been growing both on- and offshore for the past 18-24 months, according to the analysis. Gulf of Mexico (GOM) shelf production has declined, but there is higher gas output from the deepwater GOM and several other domestic unconventional resource plays.

"The strong 4Q2007 contribution from Independence Hub plus trend growth from gas shales (and other resource plays) should yield annual average per-day growth of about 3.1% in 2007," analysts said. "For similar reasons we estimate 3.1% in U.S. gas production growth for 2008."

The GOM's growth in November and December came from Independence Hub output, which grew from 0.15 Bcf/d in June 2007 to 0.8 Bcf/d in December. In the final month of 2007 gas production from the GOM averaged 8.21 Bcf/d versus 7.31 Bcf/d in September 2007 (when Independence Hub ramped up), compared with an annual average of 13.48 Bcf/d in 2000.

Onshore, said the analysts, gas growth has been lifted by Texas' output: production in only the Barnett Shale and East Texas plays last December was 17.86 Bcf/d, compared with an annual average of 14.43 Bcf/d for 2000. Louisiana production has trended down slightly. The analysis did not include the recent projections in the Haynesville Shale (see NGI, March 31). Gas output in Louisiana last December was 3.62 Bcf/d, compared with an annual average of 3.98 Bcf/d. Wyoming, however, has shown gas gains, with December production at 5.33 Bcf/d, compared with an annual average of 2.97 Bcf/d for 2000.

Raymond James & Associates Inc. played the contrarian in its outlook for summer gas demand. Energy analysts said they believe that gas demand will not be up as much as many people think because the gas bulls have ignored an expected increase of hydroelectric output, which likely will displace a lot of West Coast generation this summer.

The long-term outlook for increased gas-fired demand "is still very robust," but "it is fair to say that increased hydro this year will offset much of the underlying gas-fired electric demand growth that has occurred over the past two years," said Raymond James analyst J. Marshall Adkins.

"Given the current Northwest snowpack levels (and announced outage plans by the various nuclear facilities), we now believe that as much as 1 Bcf/d of 2008 summer gas demand could be displaced by changes in hydroelectric/nuclear power output," wrote Adkins. "This hydrocarbon demand displacement will be driven principally by increased hydroelectric power generation in the Pacific Northwest, as snow precipitation levels have been much higher than last year."

Even if there are "slightly more" nuclear outages in the Northeast, the impact of higher hydro generation "should overwhelm the planned nuclear outages," Adkins said. Natural gas predominates over coal in both the Northwest and the Northeast, he noted.

"All in, it looks like hydroelectric power generation will displace the equivalent of about 1.2 Bcf/d of gas, while lower nuclear output will increase gas equivalent demand by about 0.2 Bcf/d this summer," Adkins wrote. "Thus, if we modestly haircut the gas displacement, it seems reasonable that summer 2008 natural gas demand will be negatively impacted by 0.5-1.0 Bcf/d as hydroelectric power generation surges higher this summer."

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